Methods for strengthening fractures in subterranean formations

ABSTRACT

Of the many methods provided herein. one method comprises: providing at least a portion of a subterranean formation that comprises a shale; providing a plasticity modification fluid that comprises an aqueous fluid and an alkaline embrittlement modification agent; placing a pack completion assembly neighboring the portion of the subterranean formation; and embrittling at least a portion of the shale to form an embrittled shale portion.

RELATED APPLICATIONS

This application is a continuation-in-part of U.S. patent applicationSer. No. 12/751,770, filed on Mar. 31, 2010 now U.S. Pat. No. 8,371,384.Another related continuation-in-part also has been filed that is U.S.patent application Ser. No. 12/826,426, filed on Jun. 29, 2010 now U.S.Pat. No. 8,371,382.

BACKGROUND

The present invention relates to methods of treating a subterraneanformation, and, at least in some embodiments, to methods ofstrengthening fractures in subterranean formations having low inherentpermeability that comprise tight gas, shales, clays, and/or coal beds.

Subterranean formations comprising tight gas, shales, clays, and/or coalbeds generally have a low permeability. As used herein, the term “tightgas” refers to gas found in sedimentary rock that is cemented togetherso that flow rates are relatively very low. As used herein, the term“shale” refers to a sedimentary rock formed from the consolidation offine clay and silt materials into laminated, thin bedding planes. Asused herein, the term “clay” refers to a rock that may be comprised of,inter alia, one or more types of clay, including, but not limited tokaolinite, montmorillonite/smectite, illite, chlorite, and any mixturethereof. The clay content of the formations may be a single species of aclay mineral or several species, including the mixed-layer types ofclay. As used herein, “coal bed” refers to a rock formation that may becomprised of, inter alia, one or more types of coal, including, but notlimited to, peat, lignite, sub-bituminous coal, bituminous coal,anthracite, and graphite. Traditionally, these unconventional formationshave been viewed as having non-productive rock by the petroleum industrybecause they are “tight” and have low permeability. The term“permeability” as used herein refers to the ability, or measurement of arock's ability, to transmit immiscible fluids, typically measured indarcies or millidarcies. Formations that transmit these fluids readily,such as sandstones, are described as permeable and tend to have manylarge, well-connected pores. Impermeable formations, such as shales andsiltstones, tend to be finer grained or of a mixed grain size, withsmaller, fewer, or less interconnected pores. If a single immisciblefluid is present in a rock, its relative permeability is 1.0.Calculation of relative permeability allows for comparison of thedifferent abilities of fluids to flow in the presence of each other,since the presence of more than one fluid generally inhibits flow. Therelative differences are often categorized as high permeability or lowpermeability relative to a permeability of 1.0. Also, they requirespecialized drilling and completion technologies. Recently, however,there have been a number of significant natural gas discoveries in suchformations, which in this economic climate, have warranted production.

Fractures are the primary conduit for the production of oil and gas. Inthese applications, most of the effective porosity may be limited to thefracture network within the formation, but some gas may have also beentrapped in the formation matrix, the various layers of rock, or in thebedding planes. To make these types of formations economical,fracturing/stimulation treatments often are advisable to connect thenatural microfractures in the formation as well as create new fractures.Creating or enhancing the conductivity of the formation should increasethe production of gas from the formation. In other words, the moresurface area that can be exposed within the formation through fracturingthe formation, the better the economics and efficiency will be on agiven well.

Fracturing such formations is typically accomplished by using linear orcrosslinked gels or fresh or salt water fluids comprising a frictionreduction additive. These water type fracturing treatments are oftenreferred to as “slick water fracs.” In such treatments, often theprimary objective is to create or connect a complex fracture network,sometimes called a dendritic network, so hydrocarbons may be transportedfrom the reservoir to the well bore in economic quantities.

Problematic in these fractures and fracture networks is theclosure/healing of these fractures and or partial or complete proppantembedment resulting from increased closure stress due to high draw downpressures during production as well as potential softening of theformation after exposure to the treatment fluids. Many shales and/orclays are reactive with fresh water, resulting in ion exchange andabsorption of aqueous fluids leading to embrittlement of the rock in theformation. The term “embrittlement” and its derivatives as used hereinrefers to a process by which the properties of a material are changedthrough a chemical interaction such that a material that originallybehaves in a ductile or plastic manner is transformed to a material thatbehaves in a more brittle manner. Additionally, such degradation maysubstantially decrease the stability of fractures in the formation,which may cause a decrease in the productivity of the well.

This degradation also leads to proppant embedment. Proppant embedment isbelieved to cause a reduction in fracture width and conductivity, andmay be caused by a compression failure within the fracture. Unlike inwell-consolidated formations, proppant embedment in these types of tightformations can be as high as several proppant-grain diameters, e.g., inweakly consolidated sandstones. FIG. 1 illustrates the proppantembedment phenomena. FIG. 2 is a computer screen image illustrating thephenomena. Proppant embedment can reduce fracture width from about 10%to about 60% or more, for example almost 100%, when there is a very lowconcentration of proppant in the fracture, with subsequent reduction inproductivity from oil and gas wells. FIG. 3 illustrates a fracturehaving near 100% embedment. When this occurs, the pathway forhydrocarbons to the well bore may become obstructed, and production maybe impaired.

Clays can swell, disperse, disintegrate or otherwise become disrupted inthe presence of foreign aqueous fluids. The swelling or dispersion ofclays can significantly reduce the permeability of a formation. The useof salts as formation control additives has not eliminated formationdamage as a result of permeability reduction, but can reduce or minimizesuch damage. A clay which swells is not limited to expandinglattice-type clays but includes all those clays which can increase inbulk volume with or without dispersing, degrading, or otherwise becomingdisrupted, when placed in contact with foreign aqueous solutions such aswater, and certain brines. Certain clays can also disperse, degrade, orotherwise become disrupted without swelling in the presence of foreignaqueous solutions such as water, certain brines, and emulsionscontaining water or certain brines. Some clays, in the presence offoreign aqueous solutions, will expand and be disrupted to the extentthat they become unconsolidated and produce particles which migrate intoa borehole. Formations which consist largely of clay upon absorbingwater in a confined space can develop pressures on the order of severalthousands of pounds per square inch.

The clay materials defined above occur as minute, plate-like, tube-likeand/or fiber-like particles having an extremely large surface area ascompared to an equivalent quantity of a granular material such as sand.This combination of small size and large surface area results in a highsurface energy with attendant unusual surface properties and extremeaffinity for surface-active agents. The structure of some of theseclays, for example, montmorillonite, can be pictured as a stack ofsheet-like three-layer lattice units which are weakly bonded to eachother and which are expanded in the “c” crystallographic direction bywater or other substances which can penetrate between the sheets andseparate them.

Moreover, the fine aggregate that composes shales and/or clays can poseproblems if exposed to high stresses. For example, under high stress,shale can mechanically fail, resulting in the generation of fine claymaterials that can be highly mobile in produced fluids. In situationswhere there is high pore pressure and very little permeability, when thesystem is exposed to a low pressure environment, the surroundingformation can almost fluidize solid. For example, it is believed thatshale, when exposed to high stress and pore pressure conditions, cantransform from a solid into a semi-liquid material causing it to intrudeinto a proppant pack. This can result in shale intrusion, well boresloughing and large quantities of solids production, plugging screens orfilling separators on the surface.

In some formations, the bonding between bedding plane layers may beweaker than the bonding between particles in a given layer. In suchformations, the bedding plane may represent a weakness susceptible tomechanical failure or separation. To combat these problems, brines areoften used that contain high ion concentration so that ion exchange willnot occur and the reactivity of the shales and/or clays will be reduced.In extreme cases, oil-based fluids may be used to avoid exposing theshales and/or clays to aqueous fluids.

Sloughing of shale sections has been an on-going problem for thepetroleum industry for years. This sloughing has generally beenattributed to shear failure occurring in the immediate well bore regionwhen a circular hole is drilled into a rock under a particular stressstate. Such rock formations may comprise laminated sands and/or layeredsand/shale sequences.

As illustrated in FIG. 14, even very thin shale sections imbedded into aproductive formation can undergo mechanical failure and result insignificant solids being released into the formation. The presence ofexposed shale in either of such systems represents significant risk tofailure in many sand control completions in high permeabilityreservoirs. More specifically, the shale, when exposed to productionpressure conditions with draw-down pressure, can undergo shear failureresulting in the liberation of formation fines that can damage and pluggravel packs and screens in sand control completions.

In open hole completions in a producing oil or gas well, exposed shalesections in the open hole section will be exposed to the reducedpressures required to initiate the flow of the oil or gas into the well.Since the shale typically has low permeability, it tends to trappressure, potentially creating an imbalance where higher pressured shaleformations exist in close proximity to low pressured productiveformations. The fact that the shale traps pore pressure and is exposedto low well bore pressures causes an increase in stress, similar todrilling with a lightweight drilling fluid. This can lead to shearfailure and bore hole break outs and sloughing of solids into the wellbore.

FIGS. 12 through 17 show image logs taken in a well where boreholebreakout occurred in the shale section. Borehole breakouts are zones offailure of the borehole wall which form symmetrically at the azimuth ofthe least principal horizontal stress. The breakouts are frequentlyelongated in the direction of the borehole axis, and can be described bythree parameters: orientation in the borehole, opening angle, and radialdepth. Borehole breakouts can result in drill string damage, boreholecollapse, sand production, or loss of mud.

The use of aqueous-based drilling fluids are thought to exacerbate thisproblem as such fluids are thought to lead to swelling of the shale,causing its mechanical strength to be reduced and its susceptibility toshear failure, borehole breakout, and sloughing to be significantlyincreased.

In a stand alone screen completion, the liberation of solids frommechanically failed shale portions in the well bore can result insignificant plugging or erosion of the screens ultimately leading to acompletion failure due to lost productivity or sand production. Shaleintrusion or embedment has also been identified as a problem in“FracPac™” type completions where there can be a significant loss ineffective fracture width due to the invasion of solids into the highpermeability proppant pack. In gravel pack and FracPac completions(collectively referred to herein as “pack completions”), the shale isstill exposed to the reduced production pressures, but is supportedmechanically by the presence of gravel or proppant. In certain shaleformations, however, mechanical failure can result in extreme embedmentwhere the proppant or gravel grains are pushed into the surface of theshale resulting in a loss in permeability in the gravel pack or proppantpack. In extreme cases where there is high differential pressure in theshale, this can behave more like an intrusion of the failed shale intothe proppant pack as shown in FIGS. 1 and 2, for example.

SUMMARY

The present invention relates to methods of treating a subterraneanformation, and, at least in some embodiments, to methods ofstrengthening fractures in subterranean formations having low inherentpermeability that comprise tight gas, shales, clays, and/or coal beds.

In one embodiment, the present invention provides a method comprising:providing at least a portion of a subterranean formation that comprisesa shale; providing a plasticity modification fluid that comprises anaqueous fluid and an alkaline embrittlement modification agent; placinga pack completion assembly neighboring the portion of the subterraneanformation; and embrittling at least a portion of the shale to form anembrittled shale portion.

In one embodiment, the present invention provides a method comprising:providing a subterranean formation that comprises a shale; providing aplasticity modification fluid comprising an embrittlement modificationagent; placing the plasticity modification fluid into a subterraneanformation so as to form an embrittled shale portion of the formation,wherein the embrittled shale portion has a retained hardness factor ofat least 65% when tested using a Modified Brinell Hardness Test.

In one embodiment, the present invention provides a method comprising:providing a selected portion of a subterranean formation that comprisesa shale and having a first Young's modulus; providing a plasticitymodification fluid comprising an embrittlement modification agent; andplacing the plasticity modification fluid into the subterraneanformation so as to embrittle the shale to form an embrittled shaleportion so that the embrittled shale portion has a second Young'smodulus after treatment that is higher than the first Young's modulus.

The features and advantages of the present invention will be readilyapparent to those skilled in the art. While numerous changes may be madeby those skilled in the art, such changes are within the spirit of theinvention.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present invention, and should not be used to limit or define theinvention.

FIG. 1 illustrates a rock formation showing proppant embedment.

FIG. 2 illustrates proppant embedment in a fracture.

FIG. 3 illustrates a near 100% proppant embedment in a fracture.

FIG. 4 illustrates a typical stress strain curve.

FIG. 5 illustrates a sample showing plastic deformation in a compressiontest.

FIG. 6 shows a typical stress strain curve.

FIG. 7 illustrates a cylinder that has undergone a brittle failure.

FIG. 8 shows a stress-strain plot showing how a ductile material whentransformed to a brittle material will be strengthened as it becomesmore brittle.

FIG. 9 illustrates the Brinell Hardness Test.

FIGS. 10 A and 10 B illustrate proppant embedment.

FIGS. 11 A and 11 B illustrate proppant embedment.

FIG. 12 illustrates image logs taken in a well where borehole breakoutoccurred in a shale section.

FIG. 13 illustrates image logs taken in a well where borehole breakoutoccurred in a shale section.

FIG. 14 illustrates image logs taken in a well where borehole breakoutoccurred in a shale section.

FIG. 15 illustrates image logs taken in a well where borehole breakoutoccurred in a shale section.

FIG. 16 illustrates a true scale view of a borehole breakout in a wellbore.

FIG. 17 illustrates image logs taken in a well where borehole breakoutoccurred in a shale section.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention relates to methods of treating a subterraneanformation, and, at least in some embodiments, to methods ofstrengthening fractures in subterranean formations having low inherentpermeability that comprise tight gas, shales, clays, and/or coal beds.

Of the many advantages of the present invention, only some of which arediscussed or eluded to herein, one advantage is that these methods canminimize proppant embedment and fracture closure by modifying thesurface of the fracture faces in the formations such that it increasesor maintains its relative hardness after exposure to treating fluids. Itis believed that this is achieved through a chemical alteration of themechanical phenomena at the fracture face, which results in a preventionof the extrusion or intrusion of the rock surrounding the formation intothe proppant pack in the fracture. This is believed to reduce proppantembedment, shale migration, and the like. Moreover, it is possible thatthe fractures in tight gas, shales, clays, and/or coal beds may bestrengthened by use of the methods of the present invention, which maylead to increased productivity of a well in the formation, byembrittling the rock surrounding the fractures. Moreover, strengtheningor hardening of the rock can be accomplished by the removal of trappedwater within the grain structure of the rock. Removal of this water canresult in a reduction in volume of the rock which essentially causes theincrease in strength. Reducing the volume of the rock is one possiblemeans of increasing the effective conductivity or permeability of microfractures where the fluid leaks into. Additionally, the presence ofcations may enhance this effect, and can be present either naturally inthe formation or added to the formation with a treatment fluid. Themethods of the present invention may be especially suitable for use inconjunction with water fracturing methods, such as slickwater fracs.

At least in some embodiments, the methods of the present invention aredesigned to chemically embrittle and strengthen the exposed shale sothat it will have improved stability when exposed to productionconditions. By preventing sloughing of shale in open hole completions,for example, and embrittling shale to minimize proppant embedment, longterm completion reliability may be improved. The productive life ofgravel pack and FracPac completions can also be improved in laminatedreservoirs where shale is exposed to the completion.

As stated above, the term “embrittlement” and its derivatives as usedherein is used to explain a process by which the properties of amaterial are changed through a chemical interaction such that a materialthat behaves in a ductile or plastic manner is transformed to a materialthat behaves in a more hard or brittle manner. This may be due to afavorable ion exchange and active transport. Embrittlement may bedetermined by examining the Young's modulus and the Poisson's ratio ofthe natural rock before treatment. If the rock has become embrittled,the Young's modulus should be higher and the Poisson's ratio should belower as compared to the natural rock before treatment.

Young's modulus is the ratio of stress, which has units of pressure, tostrain, which is dimensionless; therefore Young's modulus itself hasunits of pressure. The SI unit of modulus of elasticity (E, or lesscommonly Y) is the pascal (Pa or N/m²); the practical units aremegapascals (MPa or N/mm²) or gigapascals (GPa or kN/mm²). In UnitedStates customary units, it is expressed as pounds (force) per squareinch (psi). Young's modulus, E, can be calculated by dividing thetensile stress by the tensile strain:

$\begin{matrix}{{E \equiv \frac{{tensile}\mspace{14mu}{stress}}{{tensile}\mspace{14mu}{strain}}} = {\frac{\sigma}{ɛ} = {\frac{F/A_{0}}{\Delta\;{L/L_{0}}} = \frac{{FL}_{0}}{A_{0}\Delta\; L}}}} & {{Equation}\mspace{14mu} 1}\end{matrix}$

Where:

E is the Young's modulus (modulus of elasticity);

F is the force applied to the object;

A₀ is the original cross-sectional area through which the force isapplied;

ΔL is the amount by which the length of the object changes; and

L₀ is the original length of the object.

Poisson's ratio (ν) is the ratio, when a sample object is stretched, ofthe contraction or transverse strain (perpendicular to the appliedload), to the extension or axial strain (in the direction of the appliedload).

$\begin{matrix}{v = {{- \frac{ɛ_{trans}}{ɛ_{axial}}} = {- \frac{ɛ_{x}}{ɛ_{y}}}}} & {{Equation}\mspace{14mu} 2}\end{matrix}$

Where:

ν is the resulting Poisson's ratio,

ε_(trans) is transverse strain (negative for axial tension, positive foraxial compression); and

ε_(axial) is axial strain (positive for axial tension, negative foraxial compression).

In some embodiments, the present invention provides methods that includea method comprising: providing a selected portion of a subterraneanformation that comprises tight gas, a shale, a clay, and/or a coal bedand having a first Young's modulus and a first Poisson's ratio;providing a plasticity modification fluid comprising an embrittlementmodification agent; placing the plasticity modification fluid into thesubterranean formation so as to treat the portion of the subterraneanformation; and embrittling the portion of the treated portion of theformation so that the treated portion has a second Young's modulus aftertreatment that is higher than the first Young's modulus and a secondPoisson's ratio after treatment that is lower than the first Poisson'sratio.

It is believed that ductile materials are materials that can becharacterized by a very large region on the stress strain curve wherethe material can be deformed plastically once its yield stress isexceeded. FIG. 4 shows a typical stress strain curve for a material thatbehaves in a ductile manner; this curve has two distinct regions, alinear elastic region followed by a plastic region. In the plasticregion, the shape of a specimen can be changed significantly withoutcompletely failing or breaking. An example of a stress-strain curve anda cylinder that has been plastically failed is shown in FIG. 5.

It is believed that brittle materials behave very differently and willfail before there is any significant deformation. FIG. 6 shows a typicalstress strain curve for a brittle material and FIG. 7 shows a cylinderthat has undergone a brittle failure. In this stress-strain curve, thereis little or no plastic region.

During the process of embrittlement in ductile subterranean formationsuch as a shale the formation material is transformed from a ductilematerial that can be failed plastically under stress to a brittlematerial that does not deform plastically. This may be due to afavorable ion exchange. To achieve this behavior from a single material,an alteration of the nature of the formation material is advisable. Toachieve the brittle behavior, the ultimate strength of the material willhave to increase significantly as shown in FIG. 8.

From an embedment stand point, it is evident that when the formationbehaves in a ductile manner, once the yield stress is exceeded theformation will plastically fail allowing the proppant grain to beembedded deep into the formation material. In a situation when theformation is brittle, the formation will not plastically deform meaningthat there will be no embedment of the proppant into the surface of theformation material. The combination of changing to a brittle materialand strengthening the formation allows more stress to be applied withoutloss of conductivity due to embedment.

In some embodiments, the present invention provides methods that includea method comprising: providing at least one fracture in a subterraneanformation that comprises tight gas, a shale, a clay, and/or a coal bed;providing a plasticity modification fluid that comprises an aqueousfluid and an embrittlement modification agent; placing the plasticitymodification fluid into the fracture in the subterranean formation; andembrittling at least one fracture face of the fracture to prevent clayextrusion of the formation into the fracture.

The term “plasticity modification fluid” as used herein refers to afluid that has a high pH at downhole conditions that is capable ofaltering the mechanical properties of the surrounding rock at thefracture face, which results in a prevention of the extrusion orintrusion of the rock into the proppant pack in the fracture.

The term “fracture face” as used herein refers to a face of a crack orsurface of breakage within rock.

The term “clay extrusion” herein refers to the mechanical phenomena ofthe rock in a subterranean formation surrounding a fracture intrudinginto the fracture, and thus, discombobulating the fracture face and/orenveloping the proppant in the fracture. This may include the migrationor intrusion of clay from the surrounding rock into the fracture.

The term “substantially prevent” as used herein means to prevent to ameasurable extent, but not necessarily to completely prevent.

The plasticity modification fluids of the present invention comprise anaqueous fluid and an embrittlement modification agent, and therefore,have a high pH. The pH range of the fluids is preferably 10 or above atdownhole conditions.

It is believed that these plasticity modification fluids prevent therock surrounding a fracture from migrating into the proppant pack oropen fracture, which would otherwise plug the fracture. Thus, theplasticity modification fluids are chemical fluids that counteract themechanical phenomena to prevent the extrusion mechanism (e.g., throughembrittling the rock) and the resultant proppant embedment or fractureclosure. This is believed to affect the basal spacing in the surroundingclays.

These fluids are also believed to prevent shale sloughing bystrengthening shale through embrittlement. Using these plasticitymodification fluids provides a means of strengthening exposed shalefaces to provide improved long term completion performance. especiallyin sand control operations in high permeability formations. For example.in high permeability fracturing operations, the goal is to formembrittled shale portions that are in direct contact with the fracture,gravel pack, open hole, or screen so that when it is exposed todraw-down conditions, it will not fail or cause damage to the proppantpack, gravel pack, or screen. This could have significant impact informations where stand-alone screen completions could replace moreexpensive gravel pack completions by addressing the shale problems thatare the primary cause of failure in stand-alone screen completions.

Suitable aqueous fluids include any aqueous fluid that is compatiblewith a high pH including fresh water, brines, and the like. Theconcentration of the aqueous fluid in the plasticity modification fluidsof the present invention will depend on the desired pH (e.g., 10 orabove at downhole conditions) of the fluid given the factors involved inthe treatment.

The embrittlement modification agents for use in the present inventioncomprise high alkaline materials. Suitable examples include, but are notlimited to, lithium hydroxide, sodium hydroxide, potassium hydroxide,rubidium hydroxide, calcium hydroxide, strontium hydroxide, bariumhydroxide, cesium hydroxide, sodium carbonate, lime, amines. ammonia,borates, Lewis bases, other strong bases, and any derivative orcombination thereof. The concentration of the embrittlement modificationagent in the plasticity modification fluids of the present inventionwill depend on the desired pH (e.g., about 10 or above at downholeconditions) of the fluid given the factors involved in the treatment.The effect of the plasticity modification fluids of the presentinvention is surprising because past studies have found that utilizingbases, such as sodium hydroxide, to stabilize clays has provenrelatively ineffective in that it was believed that they can promotesignificant formation permeability damage, and in some instances,actually increase the fresh water sensitivity of formation clays.

Optionally, the plasticity modification fluids of the present inventionmay comprise cationic additives, such as cationic polymers and cationicorganic additives, to enhance the plasticity modification. Divalentcationic additives may be more stable. If used, such additives may beused in an amount of about 0.1% to about 1% by weight of the fluid.Hydroxy aluminum and zirconium oxychloride are examples. Other examplesinclude the following additives available from Halliburton EnergyServices, Inc. in Duncan, Okla.: “CLAYSTA XP,” “CLAYSTA FS,”“CLAYFIX-II,” and “CLAYFIX-II PLUS.” Suitable additives are described inthe following patents, each of which are hereby incorporated byreference, U.S. Pat. Nos. 5,097,094, 4,974,678, 4,424,076, and4,366,071.

Optionally, the plasticity modification fluids of the present inventionmay comprise salts such as salts of lithium, sodium, potassium,rubidium, calcium, strontium, barium, cesium, sodium, potassiumchloride, calcium chloride, magnesium, and manganese. The ion exchangeresulting from the presence of the salt is useful in aiding in theshrinkage of the rock.

Optionally, including surfactants in the plasticity modification fluidsmay facilitate ultra low surface tensions and allow these fluids topenetrate into a matrix or micro fracture more easily.

In some embodiments, the plasticity modification fluid may be placed ina subterranean formation as a result of a fracturing treatment. Theprocess of hydraulic fracturing creates the maximum differentialpressure helping to make these fluids penetrate more readily into theformation matrix or micro fractures.

Any suitable fracturing fluid and method for the subterranean formationmay be used in conjunction with the present invention. In someembodiments, the methods of the present invention may be very wellsuited for applications using very inefficient fluids or fluids thathave little fluid loss control, such as linear gelled fluids or ungelledfluids such as water. These fluids do not tend to form filter-cakes atthe formation surface, and therefore, are capable of leaking off moreeasily into a tight formation matrix or micro fracture. Crosslinkedfluids are also suitable, but because of their improved efficiency andcontrolled fluid loss, they may not tend to invade as deeply into theformation or micro fractures.

In one aspect, the invention provides a method comprising: fracturing asubterranean formation that comprises tight gas, a shale, a clay, and/ora coal bed to form at least one fracture therein; providing a plasticitymodification fluid that comprises an aqueous fluid and an alkalineplasticity modification agent; placing the plasticity modification fluidinto the fracture in the subterranean formation; and allowing theplasticity modification fluid to substantially prevent clay extrusioninto the fracture

In one aspect, the invention provides a method comprising: providing asubterranean formation that comprises tight gas, a shale, a clay, and/ora coal bed; providing a plasticity modification fluid comprising analkaline plasticity modification agent; placing the plasticitymodification fluid into a subterranean formation so as to form a treatedportion of the formation; and allowing a portion of the treated portionof the formation to dehydrate to have a retained hardness factor of atleast 65% when tested using a Brinell Hardness Test that is current asof the filing date of this application.

In one aspect, the invention provides a sample of a shale rock having agreater than 65% retained hardness when tested using a Brinell HardnessTest (that is current as of the filing date of this application) aftertreatment with a plasticity modification fluid that comprises analkaline plasticity modification agent.

In one embodiment, a method of treating a subterranean formationcomprises the following steps: placing a treatment fluid into a wellbore that penetrates a subterranean formation, wherein the subterraneanformation comprises at least one selected from the group consisting of:a shale, a clay, a coal bed, and a combination thereof and applying apressure pulse to the treatment fluid.

In another embodiment, a method of treating a subterranean formationcomprises the following steps: placing a treatment fluid into a wellbore that penetrates a subterranean formation, wherein the subterraneanformation comprises at least one selected from the group consisting of:a shale, a clay, a coal bed, and a combination thereof; and applying apressure pulse that exceeds the formation fracture gradient to thetreatment fluid.

In one embodiment, the present invention provides a method comprising:providing at least a portion of a subterranean formation that comprisesa shale; providing a plasticity modification fluid that comprises anaqueous fluid and an alkaline embrittlement modification agent; placinga pack completion assembly neighboring the portion of the subterraneanformation; and embrittling at least a portion of the shale to form anembrittled shale portion.

In one embodiment, the present invention provides a method comprising:providing a subterranean formation that comprises a shale; providing aplasticity modification fluid comprising an embrittlement modificationagent; placing the plasticity modification fluid into a subterraneanformation so as to form an embrittled shale portion of the formation,wherein the embrittled shale portion has a retained hardness factor ofat least 65% when tested using a Modified Brinell Hardness Test.

In one embodiment, the present invention provides a method comprising:providing a selected portion of a subterranean formation that comprisesa shale and having a first Young's modulus; providing a plasticitymodification fluid comprising an embrittlement modification agent; andplacing the plasticity modification fluid into the subterraneanformation so as to embrittle the shale to form an embrittled shaleportion so that the embrittled shale portion has a second Young'smodulus after treatment that is higher than the first Young's modulus.

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, thescope of the invention.

EXAMPLES

A modified version of the Brinell Hardness Test (as defined below),referred to herein as a Modified Brinell Hardness Test, can be used tomeasure the hardness of samples of subterranean formations, in terms ofthe Brinell Hardness Number (“BHN”) relative to each other, or offormation samples before and after certain treatments such as exposureto various fluids. The Brinell Hardness Test, thus, is a measure of theresistance of the rock to indentation, which has direct applicability toproppant embedment problems.

The Brinell Hardness Test method involves indenting the test materialwith a 10 mm diameter hardened steel or carbide ball subjected to a loadof 3000 kg. For softer materials the load can be reduced to 1500 kg or500 kg to avoid excessive indentation. The full load is normally appliedfor 10 to 15 seconds in the case of iron and steel and for at least 30seconds in the case of other metals. The diameter of the indentationleft in the test material is measured with a low powered microscope. TheBHN is calculated by dividing the load applied by the surface area ofthe indentation. Formula 3 shows the calculation for the method:BHN=F/[(Π/2·D)(D−(√(D ² −D ² ₁))]

The diameter of the impression is the average of two readings at rightangles. The use of a Brinell hardness number table can simplify thedetermination of the Brinell hardness. A well structured BHN reveals thetest conditions, and looks like this, “75 HB 10/500/30” which means thata Brinell Hardness of 75 was obtained using a 10 mm diameter hardenedsteel with a 500 kilogram load applied for a period of 30 seconds. Ontests of extremely hard metals a tungsten carbide ball is substitutedfor the steel ball. Compared to the other hardness test methods, theBrinell ball makes the deepest and widest indentation, so the testaverages the hardness over a wider amount of material, which will moreaccurately account for multiple grain structures and any irregularitiesin the uniformity of the material. This method is the best for achievingthe bulk or macro-hardness of a material, particularly those materialswith heterogeneous structures. FIG. 9 illustrates the test, where 102 isthe applied force.

For the following series of Quantitative BHN tests, the BHN wasdetermined for samples of shale from the Haynesville and Woodfordformations both dry and after exposure to various fluids. The data isgiven in Table 1 showing the BHN values for before and after exposure tothe indicated fluids. The % retained hardness was calculated by dividingthe post-exposure BHN by the pre-exposure BHN and multiplying that valueby 100. The sample that was exposed to the HYBOR G fluid retainedapproximately 50% more of its initial “hardness” when compared tosamples that were exposed to the other two fluids. “HYBOR G” is adelayed borate crosslinked guar fracturing fluid available fromHalliburton Energy Services, Inc. in Duncan, Okla. “FR-56” is a frictionreducer available from Halliburton Energy Services, Inc. in Duncan,Okla. It is a liquid friction reducer that comprises an oil-wateremulsion that is easily inverted or broken and dispersed with aqueousfluids. “DELTA 200” is a borate fracturing fluid available fromHalliburton Energy Services, Inc. in Duncan, Okla., and is designed foruse in wells having a bottomhole temperature of up to about 200° F.

TABLE 1 BHN BHN % Retained Formation Fluid (pre-) (post-) HardnessHaynesville HYBOR G 8.4 7.625 91 Haynesville Slickwater with a 8.9 5.461 FR-56 friction reducer Woodford DELTA 200 23 14 61 (with nocrosslinker)

A possible explanation for the effects seen in Table 1 can be seen ifone looks at the pH of the various fluids. HYBOR G has a pH of 10.5, andthe Slickwater and DELTA 200 fluids have pHs of about 7. It is possiblethat the more alkaline solution, coupled with divalent cations presentin the formation mineralogy, served to give similar effects as limestrengthening of substrates. The effect of this hardening or reductionin hardening in a formation can best be visualized by looking atproppant embedment in soft formations.

For these qualitative Quad-Cell embedment tests, the Quad-Cell loadframe may be used to evaluate proppant embedment and changes in theformation/proppant mineralogy after exposure to closure pressures andtemperature similar to well conditions. Briefly, the experiment involvesloading a wafer of shale of about a 2″ diameter into the cell, placingproppant (slurried with the desired fluid) on top of the first wafer,and installing a second shale wafer on top. In effect, this replicates ashale fracture propped by a proppant and exposed to a treatment fluid.Closure stress is applied and the cell is heated to the desiredtemperature and held at these conditions for 2-4 weeks. After this timeperiod, the sample is removed from the cell, impregnated with an epoxy,and thin sections are taken.

FIGS. 10A and 10B are scanning electron microscope (“SEM”) photos ofthin sections take from a sample of the Woodford shale in which 0.5#/ft²of proppant has been placed with a 16/30 CRC slick water treatmentcomprising FR-56. The pack was placed in a load frame and approximately7.5K psi closure pressure was applied at 200° F. for a period of 3weeks. As can be seen in the thin sections, the proppant has in mostcases been enveloped within the formation.

FIGS. 11A and 11B are also SEM photos of thin sections from a sample ofWoodford shale, but now 2#/ft² of proppant is used with a HYBOR G fluid.Closure stress and temperature are the same as in the first test. Herethere is little to no embedment of the proppant into the formation.Again, one explanation can be found in the differences in pH of the twotreating fluids. In this sample of Woodford shale, there is both calciumand magnesium present.

These tests indicate that it is possible that a high pH treating fluidcan minimize proppant embedment and fracture closure by modifying thesurface of the fracture such that it increases or maintains its relativehardness after exposure to treating fluids.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present invention. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the range is specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” or,equivalently, “from approximately a-b”) disclosed herein is to beunderstood to set forth every number and range encompassed within thebroader range of values. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an”, as used in theclaims, are defined herein to mean one or more than one of the elementthat it introduces. If there is any conflict in the usages of a word orterm in this specification and one or more patent or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

1. A method comprising: providing at least a portion of a subterraneanformation that comprises a shale; providing a plasticity modificationfluid that comprises an aqueous fluid and an alkaline embrittlementmodification agent; placing a pack completion assembly neighboring theportion of the subterranean formation; and embrittling at least aportion of the shale to form an embrittled shale portion.
 2. The methodof claim 1 wherein the embrittled shale portion has less sloughingpotential than the portion of the subterranean before the embrittlingstep.
 3. The method of claim 1 wherein embrittled shale portionsubstantially prevents formation intrusion into the fracture.
 4. Themethod of claim 1 wherein the embrittlement modification agent comprisesa base chosen from the group consisting of: an amine; lithium hydroxide;sodium hydroxide; potassium hydroxide; rubidium hydroxide; calciumhydroxide; strontium hydroxide; barium hydroxide; sodium carbonate;lime; and any derivative or combination thereof.
 5. The method of claim1 wherein the plasticity modification fluid comprises a cationicadditive.
 6. The method of claim 1 wherein the subterranean formationcomprises laminated sands portion and/or a layered sand/shale sequence.7. A method comprising: providing a subterranean formation thatcomprises a shale; providing a plasticity modification fluid comprisingan embrittlement modification agent; placing the plasticity modificationfluid into a subterranean formation so as to form an embrittled shaleportion of the formation, wherein the embrittled shale portion has aretained hardness factor of at least 65% when tested using a ModifiedBrinell Hardness Test.
 8. The method of claim 7 wherein the subterraneanformation comprises at least one pack completion neighboring theembrittled shale portion.
 9. The method of claim 8 wherein the packcompletion comprises a gravel pack.
 10. The method of claim 7 whereinthe subterranean formation is high permeability.
 11. The method of claim7 wherein the embrittlement modification agent comprises a base chosenfrom the group consisting of: lithium hydroxide; sodium hydroxide;potassium hydroxide; rubidium hydroxide; calcium hydroxide; strontiumhydroxide; barium hydroxide; sodium carbonate; lime, other strong bases,and any derivative or combination thereof.
 12. The method of claim 7wherein the plasticity modification fluid comprises a cationic additive.13. The method of claim 7 wherein the plasticity modification fluidcomprises a salt and/or a surfactant.
 14. The method of claim 7 whereinthe subterranean formation comprises an open-hole.
 15. The method ofclaim 7 wherein the subterranean formation comprises laminated sandsportion and/or a layered sand/shale sequence.
 16. A method comprising:providing a selected portion of a subterranean formation that comprisesa shale and having a first Young's modulus; providing a plasticitymodification fluid comprising an embrittlement modification agent; andplacing the plasticity modification fluid into the subterraneanformation so as to embrittle the shale to form an embrittled shaleportion so that the embrittled shale portion has a second Young'smodulus after treatment that is higher than the first Young's modulus.17. The method of claim 16 wherein the subterranean formation comprisesat least one pack completion neighboring the embrittled shale portion.18. The method of claim 16 wherein the embrittled shale portion has afirst Poisson's ratio.
 19. The method of claim 16 wherein the embrittledshale portion has a second Poisson's ratio after treatment that is lowerthan the first Poisson's ratio.
 20. The method of claim 16 wherein thesubterranean formation comprises a stand-alone screen completion.